Naturally occurring hydrocarbon gases such as natural gas, coal seam gas, gas associated with crude oil or other hydrocarbon deposits are often contaminated with one or more undesired components. These undesired components may have to be removed to make the gas marketable. Contaminants may include, but are not limited to, acid gases such as carbon dioxide and hydrogen sulfide, water, oxygen, nitrogen, and larger than desired amounts of hydrocarbons heavier than methane. Any or all contaminants may need to be at least partially removed to make the gas marketable. Pipeline transportation systems typically impose specifications as to the amount of water, acid gases, oxygen, and heavier hydrocarbons are allowed in the pipeline system. Heavy hydrocarbons may be limited by the dew point temperature of the gas, or by the heating value of the gas.
A less common contaminant of these gases, particularly of some natural gas, is a family of caged hydrocarbons referred to as diamondoids. This family of high boiling point, saturated, poly-cyclic compounds includes adamantine, diamantane, triamantane, and heavier compounds. These components are characterized by high melting points and high vapor pressure in natural gases. When a gas containing diamondoids is reduced in pressure, temperature, or both, a portion of the diamondoid components can condense and solidify after saturation in the gas is reached. Condensation and solidification can cause fouling and plugging of the gas-handling equipment, a potentially dangerous condition. One reference for physical property measurements and predictions of diamondoid behavior is published in the “Proceedings of the seventy-third GPA annual convention”, Mar. 7-9 1994, as a paper titled “An analysis of solid-forming characteristics from a produced gas stream” by A. S. Cullick et. al. This reference includes data for solubility of diamondoids in gas at various pressures and temperatures along with melting points and relative volatility (k-value) data and prediction methods.
U.S. Pat. Nos. 4,952,747; 4,952,748; 4,952,749; 5,019,665; H1,185; and U.S. Pat. No. 5,461,184 explore and describe systems for removal of diamondoid components from gas systems, particularly removal from natural gas utilizing one or more solvents and also utilizing silica gel. In a typical system, a suitable liquid solvent with capacity to maintain diamondoids in liquid solution is injected into the gas handling system at a point upstream of where the diamondoids would form solids due to lowering of pressure or temperature. Injection points can include into a natural gas production well tubing, into a production well pipe upstream of any choke valves, and upstream of any production coolers. The solvent, containing absorbed diamondoids, is typically separated from the gas and then recirculated using a pump until it becomes saturated with diamondoids and must be replaced. Continuous regeneration of the solvent and removal and concentration of the diamondoids is also described. Regeneration using a standard refluxed and reboiled distillation tower is described, along with azeotropic distillations. The gas stream may also be contacted countercurrently with the solvent in a mass transfer operation such as a packed or trayed tower. Regeneration may also be used in this type of application. If a solvent is injected into a gas stream and flows con-currently with the gas, the solvent inhibits the formation of solids by allowing the diamondoid compounds to enter solution. At the point where the solvent is removed from the system a single equilibrium stage between the vapor and liquid has been achieved, at the final physical conditions. Appropriate solvents can hold 10% volume or more diamondoids in solution. When the solvent is not regenerated, circulation, make-up, and purge rates are set so as to control the amount of diamondoids in the solvent. When a mass transfer tower is used, a stagewise operation occurs, and the amount of diamondoids absorbed into the solvent is set by operating condition temperature and pressure, number of stages allowed, amount of diamonoids in the lean solvent, and so on. Silica gel is described as a polishing step for additional removal.
Solvents used for maintaining condensed diamondoids in solution typically contain aromatic compounds. Diesel is the most common solvent recommended. Kerosene, aromatics, mixed xylenes, and others are also mentioned. Other liquid hydrocarbons can also keep the condensed diamondoids from dropping out of solution and fouling the systems. In fact, when heavier hydrocarbons are present in the naturally occurring gas, diamondoids may not be noticed, even if they are present, as a portion of the of the heavier hydrocarbons will condense and form a liquid phase that can keep the diamondoids from solidifying, and form this liquid phase under conditions that are similar to those that cause the diamondoids to condense—such as when temperature or pressure is lowered. In this manner, the naturally occurring hydrocarbons act as a diamondoid solid inhibitor, just as injection of diesel into a hydrocarbon dry system can. In the case of condensing naturally occurring heavy hydrocarbons, the potential issue of distribution of the liquid is not a problem as it forms directly from the gas, however, distribution of an injected solvent can be a problem.
Acid gases are typically removed from hydrocarbon gases using chemical solvents such a amines, including MEA, DEA, DIPA and MDEA in a solution with water. Physical solvents may also be used. The hydrocarbon gas is often saturated with water after these processes, and may need to be removed.
Water is common is produced hydrocarbon gases. Removal of water is often required to meet pipeline specifications. Removal of water may also be required to allow for low temperature processing of the gas without hydrate formation for heavier hydrocarbon removal from the gas.
A typical pipeline specification is 7 lbs. water per MMscf of gas. This specification is easily reached with a variety of common methods. Perhaps the most common is to use a TEG solvent (tri-ethylene glycol) in a counter-current mass transfer contacting tower utilizing trays of packing. The lean TEG absorbs the water at atmospheric temperatures in the contactor, and the resulting water-rich TEG is regenerated in a second tower, with the water rejected as the overhead vapor product and the lean TEG removed as the bottoms product. This is a very common and proven method of dehydration. TEG systems are commonly installed on processed gases after initial liquid hydrocarbon and produced liquid water separation. They are also installed downstream of acid gas removal systems. TEG is a stagewise mass transfers absorption system, just as a trayed diamondoid system can be. A typical TEG system with about 99% weight TEG purity will achieve approximately 100° F. dew point depression, dependent on contactor temperature.
Dehydration of gases to lower water content may be necessary when removal of heavier hydrocarbons is desired. Hydrocarbon removal systems to meet dewpoint or BTU specification for the gas, or to enable marketing of the recovered liquid as a separate stream typically involves reducing the temperature of the gas to below atmospheric temperature. Dehydration to lower water content can be achieved with several technologies, all well proven, including use of molecular sieves (adsorption of water), membrane systems, and enhanced TEG systems that result in leaner lean solvent water concentration (enhancing the equilibrium for water absorption at the top stage of the tower), all of which may operate at atmospheric temperature. Ethylene glycol (EG) and methanol systems are common inhibition methods employed as the gas is cooled. If the gas has not been dehydrated, water will condense when the gas is cooled, and under certain conditions, typically at below 70 deg. F., methane and other hydrocarbons can form hydrate molecules that will solidify in the system. Ice will form at temperatures below 32° F. The EG or methanol will hold condensed water in solution, without allowing it to freeze or form hydrates, as long as certain well-established compositional conditions are met. Conditions include that the EG or methanol are present at the point where the water condenses, and that the solution containing water does not contain so much water that a concentration that can freeze occurs. EG is typically injected into the system with one or more spray nozzles located upstream of points where the gas is cooled by heat exchange or by auto-refrigeration associated with pressure drop. The gas containing water is typically routed through the tube-side passes of shell and tube heat exchangers in order to keep the EG in contact with the gas as it cools. Tubes can be cut off flush with the exchanger tube-sheet to allow sprayed EG to enter each tube, rather than having EG that does not directly enter a tube when sprayed to simply flow down the surface of the exchanger tube-sheet and then flow only through the bottom several tubes. Several times the theoretically required volume of EG is typically circulated, to allow for poor distribution into the tubes. One or more spray nozzles are typically used to ensure coverage of the tube-sheet. Use of EG and methanol systems are well documented in literature, and proven. A typical lean EG stream is 80% weight EG, 20% weight water. The water rejected from the rich EG during regeneration may be vented to atmosphere, or may be routed to a VOC recovery system or flare if co-aborbed hydrocarbons present a VOC, flammability, or personnel exposure hazard. EG does have a documented affinity for absorbing aromatics.
Hydrocarbon liquids may be recovered by simply reducing the temperature of the gas with a refrigeration system, and separating the condensed hydrocarbon liquid. In this simple system, EG hydrate inhibition is often employed. EG is sprayed into the gas at points where the gas is cooled, such as when the gas enters heat exchangers. The rich EG, containing water, can be separated in a separate compartment of the same separator used for separation of the condensed liquid hydrocarbon. Liquid hydrocarbon is recovered, gas hydrocarbon dewpoint is met, and the gas is dehydrated in a very simple system. This type of system is often referred to as a “low temperature separator” system, or “LTS”. Diamondoids would not typically be a problem is this type of system, as the condensing hydrocarbon components may well keep any condensing diamondoid compounds in solution.
Hydrocarbons heavier than methane are also recovered using “cryogenic” technologies, including turbo-expander plants, JT plants, and low temperature refrigeration plants. These plants are characterized as operating below the temperatures of simple LTS systems or of refrigerated absorption systems that have a typical minimum process temperature of greater than minus 40° F. Cryogenic plants are also characterized by achieving liquid hydrocarbon recovery without the use of a circulating solvent for absorption—the gas is cooled to the extent that all of the desired product can be condensed as a liquid. Water dehydration for these systems must achieve water dewpoint temperatures suitable for the minimum process temperature, typically in the range of minus 100 to −150° F. This can be achieved using molecular sieves for adsorption of water, followed by regeneration of the adsorbed water using lower pressure and/or higher temperature. Methanol may also be used, but is less common. Molecular sieve systems could be used for simple LTS or solvent absorption systems for liquid recovery, but are typically not used due to cost relative to simple EG injection inhibition systems.
Nitrogen contamination can also be removed using either absorption technology or cryogenic technology. As with liquid hydrocarbon recovery, the cryogenic processes typically use molecular sieves for dehydration upstream of the nitrogen rejection plant, and absorption systems typically use EG injection for hydrate inhibition and water removal. The absorption system for nitrogen rejection can also use molecular sieves, methanol injection, membranes, enhanced TEG systems, or others for dehydration. The absorption systems operate at warmer temperatures, typically above −40° F., and therefore EG injection is adequate and is typically employed as the most economical method for water removal/hydrate inhibition.
Absorption using a physical solvent to remove the heavier components and therefore separate them from the light components, a process known as the Mehra Process™, can be employed. The Mehra Process is described in several U.S. Patents, including U.S. Pat. Nos. 4,623,371, 4,832,718, 4,833,514, and 5,551,972. These patents describe systems for absorption/flash regeneration systems for removal of light components such as nitrogen or hydrogen from heavier components such as methane or ethylene. They address systems wherein the physical solvent used is external, meaning a made up of component(s) added to the system, and also systems wherein the physical solvent used is internally generated and is therefore composed of heavier component(s) in the feed gas. An improvement to these processes is also described in U.S. Pat. No. 6,698,237 by Thomas K. Gaskin, which addresses use of stripping gas to enhance the performance of flash regeneration systems. A further improvement is described in U.S. patent application Ser. No. 11/076,356 (incorporated herein in its entirety by reference) by Thomas K. Gaskin, which describes the use of a cryogenic temperatures in processing gases in solvent absorption systems, and in provisional U.S. patent application 60/603,933 filed Aug. 24, 2004 (incorporated herein in its entirety by reference), also by Thomas K. Gaskin. In this process, the heavier components are absorbed away from the light component(s) using a circulating physical solvent. Reducing the pressure of the rich solvent in a flash separator releases the heavier component and regenerates the solvent for recirculation to the absorber. The physical solvent may be a liquid chosen for its physical properties, one property being that it is heavier than the component to be absorbed from the light component. The physical solvent may also be made up entirely of the heaviest components of the feed gas stream. These heaviest components are those that do not readily vaporize in the flash regeneration of the circulating solvent. These absorption processes are characterized in that a feed stream comprising multiple components enters the process and two or more streams, each being enriched in at least one of the components, leaves the process.
Gas reserves that do not contain recoverable hydrocarbon liquids may have a greater tendency for containing diamondoids. It may also be that diamondoids that are present in gas streams with recoverable liquid hydrocarbons are simply not noticed or analyzed to determine diamondoid content, simply because the diamondoids do not present a problem. What this means is that a typical natural gas stream that could contain diamondoids would not typically have a low temperature liquid recovery plant associated with it, and development of systems to both dehydrate the feed gas and allow for diamondoid removal to the extent required for low temperature operation has not received much attention.
Development of gas reserves containing nitrogen has not been accomplished at nearly the same pace as development of reserves that do not contain nitrogen. Removal of nitrogen adds another cost to development of reserves, and has therefore been avoided to a large extent. Development of gas reserves that contain nitrogen that must be removed, that are also very low in hydrocarbon content heavier than methane and therefore would not have a hydrocarbon liquid recovery technology installed, and that are known to contain diamondoids in the raw gas is exceptionally rare.
Removal of water, diamondoids, and nitrogen from a naturally occurring gas stream has not been required historically. Development of the solvent absorption nitrogen rejection process operating in a temperature range of 0 to −40° F., along with applications to the rare gas that contains diamondoids and no recoverable liquid hydrocarbons, has led to the need for such a process. Any process that can improve the ability to remove diamondoids and water from the feed of a low temperature process would be appreciated as a technical contribution to the art.